Good morning. My name is Cynthia. And I’ll be your conference operator today. At this time, I’d like to welcome everyone to the PetroQuest Energy fourth quarter 2008 earnings release conference call. (Operator Instructions)

Thank you. Mr.Quantz you may begin your conference.

Matt Quantz

Thank you, Cynthia. Good morning everyone. We would like to welcome you to our fourth quarter and year-end conference call webcast. Participating with me today on the call are Charles Goodson, Chairman, CEO, and President; Todd Zehnder, CFO; Bond Clement, Chief Accounting Officer.

As you’ve come to expect, we would like to make our Safe Harbor statement under the Private Securities Litigation Reform Act of 1995. Statements made today regarding PetroQuest’s business, which are not historical facts are forward-looking statements that involve risks and uncertainties.

For a discussion of such risks and uncertainties, which could cause actual results to differ from those contained in the forward-looking statements, see Risk Factors in the Company’s Annual Report Form 10-K for the year ended December 31, 2007 as updated in the Company’s quarterly reports filed on Form 10-Q filed with the SEC thereafter.

With that, Charles will get us started with an overview of the quarter.

Charlie Goodson

During the fourth quarter, we produced 9.4 bcfe or 102 million cubic feet of gas equivalent per day, which was a 20% increase compared to the fourth quarter of 2007. Approximately 55% of our production during the fourth quarter came from our long-life basins compared to 33% during the fourth quarter of 2007.

Revenues were $66 million, with product price realizations averaging $73.76 per barrel of oil and $6.35 per mcf of gas. For the year, we produced 33.8 bcfe resulting in revenue of $309 million. Due to non-cash ceiling test write-downs, we recorded a net loss of $3.14 and $2.08 per share for the fourth quarter of 2008 respectively.

However, we realized record production growth during 2008 and have grown production at a compounded annual rate of 36% over 10 years. We ended the year with 185 bcfe of proved reserves, which is company record, it represents an 18% increase over 2007s proved reserves. 68% of our reserves are in long-life basins with 93% being gas.

On a percentage basis, proved developed reserves are approximately 73%, which continues our trend of maintaining a healthy reserve base. Had year-end oil and gas prices average $60 per barrel and $7.50 per mcf, we would have ended the year with approximately 210 Bcfe of proved reserves, which indicates that we are on-track to achieve our 2008 drill bit goal of reserve growth between 30% and 40% or staying within cash flow, until commodity prices declined and our spending slowdowns occurred in the fourth quarter.

Now, let’s move on to operations. During 2008, we participated in 150 wells achieving a 96% drilling success rate. In our resource basins, we drilled 136 wells with 100% success rate. During the fourth quarter, we initiated production from five operated Woodford horizontal wells.

The average initial production rate for this group was approximately 6.1 million cubic feet per day and the average lateral link was approximately 46,000 feet. To highlight our achievements in the Woodford consider that the first five wells that we drilled had an average initial production rate and lateral link of 2 million cubic feet per day and 2,800 feet. Respectively, relative to the aforementioned latest wells, averaging 6.1 million cubic feet per day and believe that, we will continue to see improvement in total Oklahoma production averaged approximately 25.1 million cubic feet per day, which represents a 110% increase in 2007.

We have one operated rig in the Woodford, but have stopped drilling due to weak commodity prices and relatively high service cost. We will monitor rig and other drilling cost closely and be prepared to react quickly, when project economics improve to higher prices, lower cost or a combination of both.

Approximately, 43% of our Woodford acreage is currently held by production other leases not HPP, the vast majority will expire in 2010 or later. Regarding the non-HEP leases set to expire in 2009, the drilling efforts today combined with ongoing negotiations with current lease owners, we do not expect to surrender any meaningful amount of our Woodford lease hold during 2009, unless we wanted to the Fayetteville.

We participated in 33 successful non-operated horizontal Fayetteville shale wells during the fourth quarter and our average daily production was 6.7 million cubic feet per day, which is up 35% compared to the third quarter of 2008. We are currently producing approximately 9 million cubic feet per day at Fayetteville gas.

Moving South to East Texas, during the fourth quarter, we completed our sixth well in our Palmer prospect. The wells initial production rate was approximately 3 million cubic feet per day. For the year, we drilled and completed five successful Palmer wells. Finishing up in the Gulf Coast, our Bluffs Prospect began producing in November and is currently flowing at approximately 15 million cubic feet equivalent per day.

We have an approximate 39% net revenue interest in this well. Our near-term Gulf Coast inventory consists of a balance of low risk developmental projects, as well as high impact exploration projects in established company fields.

We continue to believe that our Gulf Coast station with a tight production rates and higher margins will be a strong asset to our company especially during this low commodity price environment.

With that I will turn it over to Todd

Todd Zehnder

Thank you, Charlie.

During the quarter our, LOE per Mcfe was $1.36, which is below the range of our fourth quarter guidance. The primary reason for the lower-than-guided amounts was the strong production during the quarter combined with less money spend on hurricane repair than forecasted.

During the fourth quarter we recorded a full cost ceiling impairment of approximately $247 million or approximately $150 net of tax. The primary cause for this charge was negative price related reserve revisions associated with lower oil and natural gas prices and the lower associated cash flows with the producing reserves.

The amount booked with higher than our original estimates due to actual number and specifically our unevaluated property and deferred tax balances differing from previous estimates. There were new changes to our originally guided reserve of PV-10 amount.

DD&A on oil and gas properties in the fourth quarter was $4.2 per Mcfe. We are guiding a significant reduction in DD&A for both the first quarter and full year of 2009, primarily due to the ceiling test impairments recorded during 2008.

During the quarter, we spent approximately $60 million in capital expenditures. The breakout of this capital is approximately $48 million of direct CapEx., $8 million of G&G cost, property and lease acquisition costs, and $4 million of capitalized overhead and interest.

Our 2009 drilling capital budget, which includes capitalized overhead and interest is approximately $80 to $100 million, which we plan on fully funding with our internally generated cash flow. We plan to allocate approximately 71% of our 2009 CapEx to our long-life assets.

We currently have a borrowing base of $150 million, of which we had approximately $130 million outstanding as of December 31st. We had approximately $24 million of cash and a hedging asset of approximately $41 million as of December 31,2008.

We will be focused on liquidity during 2009, while staying in line for preserving a stable reserve and production base. Our plans call for producing between 105 and 110 million cubic feet equivalent per day net for the company for the first quarter of 2009. And between 90 and 100 million cubic feet equivalent net per day net for the year ended December 31, 2009.

We increased our first quarter guidance from previously issued guidance. We also released our cost guidance today and we are confident that we will continue to live below internally generated cash flow. We plan to use the expected free cash flows to build liquidity and strengthen our balance sheet.

We currently have approximately 20.9 Bcfe or approximately 60% of our 2009 production hedge at an average floor of $8.2 on a Mcfe basis and approximately at 3.7 Bcfe of our 2000 production as hedged at a floor price of $6 per Mcfe.

We will continue to seek opportunistic times at add our hedging position. As you can tell, our primary goal for 2009 is to build our liquidity position while maintaining our stable reserve and production base.

We will continue to assess our capital program and spend dollars where the rates of return are acceptable. We feel that service costs are trending in the right direction and final being in position to resume our growth mode in future.

With that I will turn it back to Charle.

Charlie Goodson

Thank you. Looking back on 2008, we continued our transition from a peer Gulf Coast to a resource company with long-life assets. We now have approximately 68% of our proved reserves located in low risk, repeatable resource trends and that percentage is expected to be higher should product prices recover.

Also, approximately 51% of our production comes from long-life assets. We have not only diversified our assets, but we have substantially de-risked the company. This past year, we faced and overcame many challenges such as back-to-back major hurricanes and renegotiation of our credit facility during a global financial crisis. I am very proud of our employees, which all played an instrumental role in achieving record reserve and production growth for the fifth consecutive year.

Even though the current climate is very challenging, we as an industry and this company have faced similar commodity price downturns. I strongly believe that our company has and will continue to make the right strategic decisions to not only ride out this turbulent period, but to emerges as a stronger company on the other side of this cycle.

Having started this company in mid-1985 shortly before the 1986 collapse of the energy industry, a collapse that extended into the early 1990’s, we feel our industry has a portal as to how to position for these turbulent times. Having gone through this previous period at a time, other sectors of the economy were showing no signs of weakness and actually benefited from weak commodity prices created a survival instinct within our industry that is alive and well today.

The only need to look around at the pull back that has occurred in the last six months and that becomes obvious, it is my feeling that the necessary adjustment have and are being made by PetroQuest and others that will hopefully decrease the time necessary to realign the supply and demand of natural gas in North America.

As we watched a new administration set both short and long-term goals for our country, I urge each and every one of you to advocate the continued and expanded use of this abundant natural resource, natural gas.

We have all witnessed an unbelievable transformation of both a company and industry from one that struggled with growth to one where growth is relatively assured with the abundant resource projects that exist.

However, it is apparent when listing to immediate politicians and other so called non-industry experts, we must continue to enlighten them that ours, the natural gas industry is one that they can rely on and trust for decades.

A couple of questions. If you look at your budget, it sounds like you still have one rig in Woodford, did you say it’s not currently drilling now, Charlie?

Charles Goodson

That’s correct.

Ronald Mills - Johnson Rice & Company

And I am just trying to get a break down. If you look at your $80 to $100 million budget you said about 70% of it will be spent in long-life basins. How do you get to that level if given your current activity levels, how would your activity levels trend to be able to spend that much capital in those places, the Woodford was as I recall, the biggest component of your long-life spending?

Todd Zehnder

Ron, that assumes that, that rig is back to work here in a about a month or two. We are waiting to see the continued trend of service cost and we are seeing pull back across every area of service cost. The rig makes up one piece of it so we made the decision to go ahead and we’ve got already a couple of completions that are stacked up and we are going monitor that. We do assume that we are going to get that rig back to drilling, we are just waiting to better align the cost structure knowing that this gas price is so much weaker than we have expected.

Charlie Goodson

We also had a lot of non-op AFE sitting out there that we will be drilling and like Todd said, we anticipate some clarity later in the year and it’s probably going to be in the form of service costs coming down and we will be able to take a back up and hope to increase.

Ronald Mills - Johnson Rice & Company

Okay. And what’s your completion plan, I know in the Woodford it sounds like you kind of creating a little bit of backlog of completion opportunity is in and as it relates to that what’s the plans with your 7000 foot lateral that you talked about in January’s release.

Charles Goodson

Well, I really, at this point, the well is still flowing at a, may be a couple of million a day, they hadn’t looked at a recent rate on it. There is really no reason in our opinion to go and spend the capital, the frac the other 20 or so stages. Because, the rate of return on that is not acceptable to us. So it does really no good to expand that capital until gas prices come back with the known fact that service costs are continuing to go down and if we fraced it right now, we would almost be guaranteeing a work rate of return than by delaying it.

So, we do have anticipation of completing or I guess recompleting that well if you will and putting the additional stages on. It is just that we got a little bit of a, I wouldn’t call it a luxury, but we have time on our side and that is, if that going to be at a hard time in discretion.

The other well that’s been cased off, it is just a matter of whenever we want to go out there and do it. We’ve got obviously strong production. We are at a record rate, we’ve been at a record rate you can see that from our production guidance. But every dollar that we spend is going to be assessed to see if it makes sense spending now or waiting.

Ronald Mills - Johnson Rice & Company

And just two last parts, just mop-up surely from a pricing standpoint, I know we have talked about this but also just looking at regional prices. The pricing differentials have widened quite a bit. Would you expect that to continue over the remainder of the year or as Nimax has come down to the low 4s now, have those differentials started to improve a little bit in some of your fields?

Todd Zehnder

I think in general, just by nature of the gas price is coming down; the differentials have contracted a little bit. I would say that we don’t anticipate being back to I guess $0.30 or $0.40 where they were a couple of years ago, until some infrastructure projects in that region have been completed. One of the things that I am going to point out is that realized prices did come in lower, a big factor of that is the basis differentials in the mid continent.

But also as the NGL prices, which are a function of our gas production contracted during the fourth quarter that had an impact on our differentials this quarter compared to in prior years or in prior quarters. So as we see stabilization in NGL prices and so forth, we would expect to have a little bit of upside to those natural gas differentials on a blended basis as a company.

Ronald Mills - Johnson Rice & Company

Okay. And then lastly, just assuming that supply starts to respond like a lot of people are starting to suggest later this year. How quickly can you ramp back up activity in the couple of your areas as you look to exit 2009?

Todd Zehnder

Since we control operations on most of our assets, we can very rapidly, you saw how fast we were able to increase rigs in Oklahoma in a period of and we were actually planning on and we were in a position to move to four or five rigs mid-year of last year. We are positioned with locations in [inaudible] it allowed us to ramp up pretty rapidly. In Arkansas, that’s the function of others.

And in the Gulf Coast, you are going to see us increase activity as the service cost of some of these burgeon jack-ups have come down, which they are doing, those activities will be later this year. So I think we’ve said all along this is going to be back end loaded year and as soon as you and we see the clarity that we need, we are ready to go.

Operator

Your next question comes from Rehan Rashid - FBR Capital Markets.

Rehan Rashid - FBR Capital Markets

Yes, just real quickly on expanding on Ron’s questions, may be a timeline from the day you decide that you need to ramp backup, is it three months, is it two months to get some reasonable number of rigs back up on line?

Charlie Goodson

Yes, Rehan, I’d say that in Oklahoma, you could probably increase a rig every thirty to forty days. We’ve been pretty judicious in our increase of activity to make sure we didn’t front run, infrastructure and activities and so, I think if what’s to say you had a September 1, everybody decided let’s get rolling. I think that by the end of the year, you could certainly be at two rigs and possibly be at three rigs in that area.

Rehan Rashid - FBR Capital Markets

Okay. Any thoughts on may be picking up some working interest on the Woodford side, probably some other smaller guys that might not have even capital to hold on to the acreage?

Charlie Goodson

Well, I think we are up to 48,000 acres right now and as you heard in my comments, we are not going to lose, basically hardly anything up there, and what we see Rehan, there is certainly, we’ve talked about that there is available positions up there and a lot of it’s coming to us where people have participated with us in wells and they’ve seen the results at our wells compared to other ones they participated in. And so, I think there is certainly an opportunity, when we feel like it’s prudent to pick up additional acreage in that area.

Rehan Rashid - FBR Capital Markets

And any updates on the decline rates on the Woodford side, and you have a few more wells for a bit longer, is it inline with expectations? Is it holding up little bit better than you would have thought?

Charlie Goodson

I think, it’s probably safe to say that it’s holding up as good or better than we originally had booked reserves on. And we will continuously monitor that, we have had no negative surprises, obviously the negative on our reserve fees was the pricing at year-end. But, the decline curves that held up very well.

Rehan Rashid - FBR Capital Markets

And may be looking out a year, might have a few months let’s just say and may be anticipating some service costs reductions. What gas price would that you have some reasonable if not most optimal rate of returns for you to be start being active again?

Todd Zehnder

We’ve got budget sensitivities right on that rate Rehan and it really depends on the individual components of the service cost we have a case to be made if we can get service cost down and we can talk about the different AFE amounts, but I think you can make money in this basin if the service costs align themselves with where gas prices are in a $5 world. But service costs have to come off pretty dramatically from where they are before that happened, which is why we are not out there just spending away right now.

Charlie Goodson

Rehan, we have basically looked at every component of the well and we are watching those literally weekly, wrapping those things as they are coming down talking to the service providers and we would love to see the gas price move back to $7.50 or $8 and everybody could go back and what they were doing in mid-90s and 2008. But we don’t think that’s realistic.

We are having very prudent and organized discussions with these guys and I think that as Todd said it doesn’t have to get anywhere close to where the prices were before, $5 range should allow us some really good returns and as you also seeing some higher EUR’s on our wells, these longer laterals and closure spacing tracks, it doesn’t it take what it did back in late 2007 or early 2008.

Operator

Your next question comes from Dave Kistler - Simmons & Company

Dave Kistler – Simmons & Company

Yes. Quick question on the Woodford rig that you guys have idled right now, is that under contract?

Charlie Goodson

It is. We’ve done our contract through the second quarter basically.

Dave Kistler – Simmons & Company

Okay and I guess, so that leads to two questions. One; if service cost don’t fall fast enough, would you let it go? And two; I know you are looking at all the costs of the well, but does it make sense to go ahead and at least use it to drill and not complete at this standpoint, just trying to get clarity around both of those?

Charlie Goodson

I think in answer to your first question. Absolutely, we would let it go if the service costs don’t come back, because the last thing we are going to do is make an investment decision that doesn’t provide a good rate of return. The second part is something we are analyzing more on like Charlie said, a week-by-week basis. Obviously, we’ve done, we’ve got a couple of wells in backlog position.

What we are trying to figure out is does it make sense to drill some more of these and case them off. The reality is what you be doing that for is to use the rig that you have under contract and/or save some acreage and we don’t think that it just drilling a well and not fracing it will save acreage. So, as service cost, the other components in drilling the well continue to come down that will be a decision where we may put that rig back to work. But, right now it’s been more prudent for us to just recently put it in on the side lines.

Dave Kistler – Simmons & Company

Okay, I appreciate the color. And then just kind of on a ball park, how far have the service cost come down to-date and how much further do you really kind of need them to fall in order to be able to go to work in kind of a $455 gas environment?

Charlie Goodson

Well, I think different components have come down different percentages right and at this point, we think that we have probably seen about 10% to 15% decline in general service cost across the Board, some components of operating cost have fallen more than that, things like fuel and things like water hauling and so forth have come down more. If we froze gas at 4.50 to 5 bucks, we probably still need another 15% or 20% decline would be my guess just going up the top of my head Dave. Unfortunately, we’re not at 4.50 or 5 right now. And so may be we are being a little extra cautious with some of our moves here.

Dave Kistler – Simmons & Company

Well, I appreciate that color and just kind of helpful to get a sense for how far service cost still have to come down. Jumping over to liquidity for a second, if I recall correctly, when your facility was done back in October it was actually set at 300 million and you guys only decided to have a borrowing base of 150, is that correct?

Charlie Goodson

Yes. The facility amount is 150 but the borrowing base is set based by the bank on a reserve basis. Yes.

Dave Kistler – Simmons & Company

Okay. I just, what I am trying to get at is with the reserve revisions at what not and with pricing revisions also associated with that, where that might go and whether that puts any pressure on possibility of being overdrawn on a facility clearly $23 million in cash hedge position things like that, but just trying to get a little bit more color or comfort there?

Charlie Goodson

Sure. Basically, we have no reserve revisions from when we did the borrowing base. We borrowed on a reserve number that I think was slightly lower than our year-end amount and we’ve done additional drilling since then. We will have production run off and obviously the price debt that is out there being used is lower than where we where at October. With that being said, we can’t speak as to what the exact number is, the people or the banks will give us.

However, we feel pretty comfortable on our liquidity position for 2009 and beyond. With that being said, we don’t control everything that’s done by third parties, which is why we outlined a plan that appears to be pretty conservative by some of the members on the street or some of the analysts on the street, because we want to keep that ball on our court and make sure we understand cash flow to be aligned with our bank group and show that we don’t have a liquidity issue at this company.

We, at the same time want to maintain stable reserves in production, but I had mentioned on the call the number one goal for 2009 is liquidity.

Dave Kistler – Simmons & Company

Great that’s very helpful and then one last question on the CapEx. Is that front-end loaded the $80 million to $100 million or is it spread pretty evenly throughout the year?

Todd Zehnder

Well it is definitely not front-end loaded now, because we have deferred some of this Woodford drilling and so forth, it’s pretty evenly throughout the year maybe depending on kind of when we get back to drilling in the Woodford is dictated on that, but I think from a high level model standpoint you can probably just say it’s pretty evenly spread.

Some of that is out of our control from the standpoint of outside operated AFE, which will make up probably 25% to 35% of our expected CapEx in this model. And I think that’s a fully burden view of non-operated capital. I don’t think it will be any higher than that.

Dave Kistler – Simmons & Company

Well thank you guys very much for the added color there.

Todd Zehnder

Sure.

Operator

Your next question comes from Steve Berman - Pritchard Capital

Stephen Berman – Pritchard Capital

Let me start with non-operated on the Fayetteville, talk a little bit about that in terms of what you are seeing directionally in terms of what the rates of drilling look like going forward, as Fayetteville is suffering from some of the same issues obviously as the Woodford?

Charlie Goodson

I mean clearly Steve; we’ve seen a dramatic pullback in the number of wells being drilled. We are out there with the major operators and as other areas have taken the focus of their capital the Fayetteville has slowed down, which quite honestly with us is okay right now, because we would rather drill these projects when gas prices and service costs are better aligned.

Stephen Berman – Pritchard Capital

And one more balance sheet question. In terms of an option of raising liquidity, would you consider monetizing some [your] of in the money hedges, is that on the table as a possibility?

Charlie Goodson

If you needed to Steve, you could do that or if you had the view that we’ve hit a bottom? You would do that. But, that’s more of in my opinion a trading call and we’ve never been an organization that says, we trade, we hedge to protect the balance sheet and we are pretty happy with the hedging position that we have in place. If you had a short-term liquidity issue, you could do that, but we would rather leave those hedges in place to protect against, which could be even large gas prices than we are seeing right now during the summer and fall.

Stephen Berman - Pritchard Capital Partners, LLC

It makes perfect sense. Getting back to the Woodford, can you say currently taking into account any firm transportation deals you have, what kind of differentials you are seeing in your pricing?

Charlie Goodson

Based on wide or on individuals?

Stephen Berman - Pritchard Capital Partners, LLC

Just in the Woodford.

Charlie Goodson

Well, if you look at the gas that we have on our firm transportation, we can get you some more information on it, but it probably in this gas price environment ranges from $1.60 to $1.80 off of and that’s fully loaded for the fuel, the transportation, the gathering, the marketing every thing. Just the basis, between Centerpoint and Henry Hub, you guys can obviously see that real time like we can. It’s still hanging out there at probably excess of $1 right now, probably $1.20, right now.

Stephen Berman - Pritchard Capital Partners, LLC

And the first quarter production guidance, the 105 to 110, does that have any incremental operated Woodford in there, does that assume just nothing further?

Charlie Goodson

That assumes no new completions from this point forward in the first quarter.

Stephen Berman - Pritchard Capital Partners, LLC

And in terms of specific infrastructure, that might help on these differentials, I mean for example yesterday, I was listening to [inaudible] and he talked about the rigs pipeline helping definitely in the Anadarko part of Woodford in terms of narrowing differentials. Any specific pipelines that you see coming in over the next quarter or two that you expect to help in your part of the Woodford? And or the Fayetteville?

Charlie Goodson

Generally, we are carrying more capacity on boardwalk I believe and then may be the mid-continent express is the next one we’re hearing. But I can get some more information for you of that off-line.

Operator

Your next question comes from Andrew Coleman – UBS.

Andrew Coleman – UBS

I’ll just build on Steve’s question a second ago, right on the transportation issues. Do you have any backlog arrangements in place or I guess what things are looking at to improve your basis in the mid-continent?

Charlie Goodson

Well we have a firm transportation deal already Andrew that is tied up to Henry Hub. So I think we are covered from that standpoint. We were looking at expanding upon that deal when we were thinking about going to four or five rigs. But with the activity that we have outlined right now, we should be fully covered.

Andrew Coleman – UBS

And then just wanted to get a clarification on one point that was mentioned earlier, it was the break down of your long-life production at year-end and I think you’ve given one for the current, was this like 51% currently or like in the 40% range at year-end?

Charlie Goodson

I think for the quarter we averaged 55%, because we had deferred the production with the hurricanes and so forth. Going forward, it will be a little bit more skewed to Gulf Coast, I think its 55% Gulf Coast, 45 is that right guys.

Todd Zehnder

50/50

Charlie Goodson

Maybe closer to 50/50 for our 2009 estimate.

Andrew Coleman – UBS

And then can you give any breakdown on the puds that will be in your, I guess a breakdown between onshore and offshore, I mean is it fair to think that most of those puds as being related to unconventional plays.

Todd Zehnder

Absolutely, the resource plays dictate most of the pud booking, I think we have a 27% total company pud percentage and as far as South of Louisiana and the Gulf of Mexico go, that would only make up probably three, four B’s out of the total amount. So most of those puds would be located in Fayetteville, Woodford and East Texas and obviously those numbers would generally go up in a higher gas price environment.

Andrew Coleman – UBS

Okay. And then I guess from a mechanical standpoint, looking at if the futures curve is [inaudible] and we get to a much higher price here later on the year. And how quickly I guess where would we see those revisions come back I mean I look at your reserve bookings here over the last kind of 10, 12 years. I don’t see any or we saw big revisions between like 1999 and 2001. The stock prices dampened and we saw some big bookings come back in, is that what I’d be looking for is that over a two or three year period that you’d see more smoother run rate even though you may get a deep here in 2008, 2009 pricing?

Charlie Goodson

That’s a lot. I think in general with the change in the SEC pricing we’re going to be watching how ‘09 reserves are going to be booked on an average for this year. So the longer we hang out in this lower price environment, the more likely those reserves would have a greater impact to be booked in 2010 and forward.

So, if it was a year-over-year pricing and we thought the gas prices would correct themselves on the last day of 2009, yes sure, you will see a huge ramp up in this year. But I think, generally what you will see is we’ll just continue to add those in through continued production and gas price recovery and I don’t see a one-year super spike if that is what your are asking.

Andrew Coleman – UBS

Sure. now it just I think that Charlie mentioned earlier that there was a $60 and kind of $6 prices that you would have had I think 210 Bs to that additional 25 Bcf of latent potential kind of lurking there with a price realizations, could you get some of that over the next couple of years?

Charlie Goodson

Well, absolutely and that doesn’t most of that would not require incremental capital.

Andrew Coleman – UBS

Okay. And then last question there I didn’t see any thing in the releases on it. So, can you give just any color on the learning’s that came out of the lock and tear? I mean was that a seismic collaboration issue and I guess then talk about any additional high potential targets that you might be looking at for 2009 even though you don’t have it listed on your presentation?

Todd Zehnder

No, what happened there Andrew was the generator wanted that well to be drilled to an ADAC potentially ADAC set of reserves and somewhere between 10 and 50 Bcf potential and what we ran into was a lost circulation of lower pressure. And so we never tested the objective and we all feel that simply moving the location probably 1500 feet away from that Shale fall block and not having to content with that is the way to move forward.

It was a unanimous decision by the partners to do that and we were prepared to move forward until obviously the downturn and so now we are simply waiting for either gas prices to move back up or drilling cost to come back down. And so there can be no conclusion drawn from the TNA of that original well, it didn’t test the objective and we are still all just as optimistic and enthusiastic about drilling that well at some point time in the near future.

Andrew Coleman – UBS

Okay. So that was basically just a referral of the reentry that had been talked about a few months ago?

Todd Zehnder

Right.

Operator

Your next question comes from Brian Corales - SMH Capital.

Brian Corales - SMH Capital

Most of my questions have been answered but just how flexible is the capital budget and really what’s the major difference between the range. Is it just other additional wells in the Woodford?

Todd Zehnder

The capital budget probably, I can’t quantify it right now, but it is very flexible, I mean we’ve got additional wells being drilled that we don’t have committed to. So it’s flexible. The range is because, we’re not good enough to put a specific to the million dollar and we just want to be able to say this is generally where we see it. The only things we have committed to right now are outside operator wells, some existing P&A type activity which is not too significant. And then the capitalized cost that would go into as being overhead and interest and the rest of it we plan on spending, but we are going to wait until it makes sense from a return standpoint.

Brian Corales - SMH Capital

I guess you said you couldn’t, is it roughly about half of the budget you put out say 40, 50 million?

Todd Zehnder

I would say generally not knowing exactly, I would say that’s probably fair to say that at least of it is probably discretionary.

I think it was 350. If you look at the change in the full cost tools Subash, 350 in terms of cost incurred fully loaded.

Subash Chandra – Jeffries & Company

Okay. And then in Woodford, so what’s your latest thinking on the economics. And if you can or care to just talk about perhaps reserve bookings in the Woodford in ‘08?

Charlie Goodson

Well, as far our latest thoughts, we feel like we’ve gotten to a point where we gotten to drillings at 4000 to 4500 feet with clusters spread out about 350 feet per frac stage as an optimal well. We have two extend laterals that we are one of them. We have deferred the major completion aspect of it.

So, we will be testing that theory and we think that will probably have a place for the basin. But, just from a stand point of our standard type well 4500 to 5000 feet in these clusters. We feel like those are going to be optimal wells, as far as reserve bookings, it obviously is going to depend on the price, because the tail of these reserves gets cut off on a lower price environment. And that’s what impacted us.

We were well on our way to booking, significantly higher than our original estimate per well. It’s just that with the lower gas price, you lose a lot of reserves and a lot of value that way. So I don’t know if we have a pure number that each one of these things was booked out. But we were clearly on our way to upwards of 3, 4 Bcf per well with this new technology, just a new way of drilling these wells.

Subash Chandra - Jeffries & Company

Okay. So, if you look at just a model first year decline and a tail et cetera, et cetera; what’s your latest thinking on the economic break-even price required to get some sort of hurdle threshold, I mean I heard a rate here, may be a 20% rate of return or something.

John, I guess what I am trying to address is that the play is still thought of as a fairly high cost play I think, new field helped change the tone a little bit a week or two ago. And if you see any of what new technologies could help you here, first of all. Second; is what kind of hurdle you might price or you might need based on the latest string of 6 million a day wells?

Charlie Goodson

Well, I think like we said earlier, it really depends on the service cost. And it’s going to be directly related to the well AFE’s and we are seeing those costs come down. So, and a service cost environment that we think is coming to see us, you can still make money in this play at $5 or somewhere in that range. It’s just that the service cost has to come down to a level. And I don’t have an exact number for what the AFE is necessary.

The one thing that you hit on earlier is the first year decline rate is lower than we were originally expecting, I think you probably are looking in the upper 50% to 60% decline rate in year one. And Matt or myself or Bond can talk you through the exact decline rate year-by-year that we’re using off line. But, obviously the well EUR’s have gotten better, the technology has gotten better. And we are looking at all the new technology including all the new techniques that are being used and the Woodford as well as the other shale plays. So I think, overtime you will continue to see the EUR’s improve and the IP rates improved, and we’ve clearly made tremendous progress as evidenced by our last five wells. Right now, at this gas price though it just doesn’t make sense for us to deploy a bunch of capital.

Subash Chandra - Jeffries & Company

And one more from me and I will hop off the line. Just one more last Woodford question, $2 million a day and the $6 million a day wells, have you sort of seen a big change in cost between those wells or do you think the efficiencies have been achieved?

Todd Zehnder

No, we have made tremendous efficiency improvement.

Charlie Goodson

Subash I read your report and I differ a little bit about it, because I think there was some pretty dramatic shifts in cost structure that were happening for us, we can’t talk about every body else, but the wells that we were drilling. The EUR’s were coming up, there was a lot of “hanks” about us drilling the 7000-foot lateral, it went very smooth.

And you look at your cost per lateral foot drilled and the EUR per lateral foot, I can’t lay it out on the conference call, right here. But they were increasing dramatically. And so we saw nothing that was going slow us down from moving mid-year by year-end to 4, 5 and then continuing increase in drilling rigs out there.

So, I think that this pricing environment in the short run hurt everybody, but in the long run it’s probably going to be good that we pull back here. We look at these production rates, which are holding in very well. The technology I think, was changing pretty dramatically and I think you will come out of this thing seeing, ramp ups in activity certainly early next year and hopefully later this year.

Subash Chandra - Jeffries & Company

Just a follow-up if I could sneak in. Do you a well cost then on sort of the latest batch?

Todd Zehnder

Right now, we are expecting if we were to go out and drill a well, right now. One of these standard type wells. We would expect it to be somewhere around 4.9 million, I think and so we are going to be continuously trying to reduce that, is that what you are asking?

Subash Chandra - Jeffries & Company

I’m sorry.

Todd Zehnder

Is that what you are asking?

Subash Chandra - Jeffries & Company

Yes, exactly, yes. And Charlie what I would say is I think, there is good news in the Woodford and somehow and the company discussed their results, it doesn’t come across to the investor base. So, anything you can continue providing to that extent people need hear more of would be my opinion.

Operator

So, our next question comes from the line of Richard Tullis - Capital One Southcoast.

Richard Tullis - Capital One Southcoast

I think most of the questions have been touched on already. Just to get an update I know we have talked about this in the past, but just to get an update on any progress you may have had trying to work through that Haynesville ownership issue with Chevron?

Charlie Goodson

Nothing, at this point in time.

Richard Tullis - Capital One Southcoast

Okay. Looking at the 80 million to 100 million CapEx budget, how do you see it split between the major areas just in general?

Charlie Goodson

In general, it’s about 70% long-life with the majority of that going to the Arkoma Basin. The breakout is pretty flexible right now once again, quite honestly if gas prices don’t start improving or service cost don’t come down at a rate that we are happy with, the only play that could make money at $3 or $2 in our opinion are some of these high impact Gulf Coast wells.

So you may see us spend less money overall, so the percentage would increase to the Gulf Coast. Now we think that would be a short-term phenomenon, so that’s we are kind of going out there with the 70% long-life, 30% Gulf Coast. And I think in our latest investor presentation out there on the net, we got a broken out by region.

Richard Tullis - Capital One Southcoast

Looking at the Fayetteville, I imagine that Petrohawk is pulling back a bit there and I think you referenced that earlier. How many wells were you guys planning to have drilled there?

Charlie Goodson

I think gross wells; it’s still pretty high. I’m thinking our latest model somewhere around 50 or so which if we may net 10% across the play or something like that, depending on which sections get drilled. But in general, knowing that most operators in that basin have slowed down like everybody else, our gross well count is going to come down pretty dramatically.

Todd Zehnder

One last think and also on that Gulf Coast, Gulf of Mexico on some of the projects that we could easily pull out, there is an imputed promote, because those are coming fields that we own and we have partners and there is an up tick on the spending the affects of drilling those wells it really does not show up in the spending.

Operator

Your final question today is a follow-up question from the line of Ron Mills - Johnson Rice.

Ronald Mills - Johnson Rice & Company

Todd what did you say the hedge position was valued out a current prices?

Todd Zehnder

Current prices or at year-end.

Ronald Mills - Johnson Rice & Company

I guess the number you gave was it a year-end.

Todd Zehnder

Yes. That was a year-end number.

Ronald Mills - Johnson Rice & Company

So it’s only gone up since then.

Todd Zehnder

Absolutely, and we have laid in some more hedges since year-end that unfortunately continue to grow in the money.

Ronald Mills - Johnson Rice & Company

And then just as a “strengthen your balance sheet” I assume what you will do a lot of this free cash flows is pay down the borrowings on the revolver in the interim from modeling standpoint, is that fair?

Todd Zehnder

Yes. Just demand improve in liquidity is all we are going to.

Operator

At this time there are no further questions, management are there any closing remarks?

Todd Zehnder

Thanks for your time and we look forward to continue to get to this year.

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